Protective relaying generally involves performing one or more of the following functions in connection with a protected power or energy system: (a) monitoring the system to ascertain whether it is in a normal or abnormal state; (b) metering, which involves measuring certain electrical quantities for operational control; (c) protection, which typically involves tripping a circuit breaker in response to the detection of an short-circuit condition; and (d) alarming, which provides a warning of some impending problem. Fault location is associated with the protection function. It involves measuring critical system parameters and, when a fault occurs, quickly making a rough estimate of the fault location and of certain characteristics of the fault so that the power source can be isolated from the faulted line; thereafter, the system makes a comprehensive evaluation of the nature of the fault. A fault occurs when a transmission line element, due to external causes, diverts electrical current from its normal path.
The major types and causes of faults are: insulation faults, caused by design defects, manufacturing defects, improper installation, and aging insulation; electrical faults, caused by lightning surges, switching surges, and dynamic overvoltages; mechanical faults, caused by wind, snow, ice, and contamination; and thermal faults, caused by overcurrent and overvoltage conditions.
A fault may cause current in one or more of the phase lines (referred to herein as the "a", "b", and "c" phases) to be diverted to ground, to a neutral line (denoted "n"), or to another phase line. The phasor diagrams in FIGS. 1A-1E illustrate the effect of faults on the system voltages and currents. The diagrams are for effectively grounded systems wherein the neutral is solidly grounded; however, they are illustrative of the effects of faults on other types of systems, e.g., ungrounded and impedance grounded systems. In the diagrams, the dotted, uncollapsed voltage triangle exists in the source (the generator) and the maximum collapse is at the fault location. The voltages between the source and fault will vary between these extremes. The diagrams depict the effects of various types of faults on the currents and voltages (represented by phasors) in the system. FIG. 1A depicts the phasors for normal, balanced conditions; FIG. 1B depicts the phasors for a three-phase fault (V.sub.ab =V.sub.bc =V.sub.ca =0 at the fault); FIG. 1C depicts the phasors for a phase b-to-phase c fault (V.sub.bc =0 at the fault); FIG. 1D depicts the phasors for a phase b-to-phase c-to-ground fault (V.sub.bc =V.sub.bg =V.sub.cg =0 at the fault); and FIG. 1E depicts the phasors for a phase a-to-ground fault (V.sub.ag =0 at the fault).
The present invention relates to fault location and fault typing in connection with electrical conductors of a power transmission system. The term "transmission line" as employed herein is intended to cover any type of electrical conductor, including high power conductors, feeders, and transformer windings.
One of the functions of a protective relaying system is to identify the type of fault. Fault type identification, or fault typing, includes determining whether the fault is between phases or between one or more phases and ground, and determining the specific phase or phases involved in the fault. The prior art employs comparisons of different combinations of currents and voltages to determine fault type through predominantly analog techniques. For example, U.S. Pat. No. 4,795,983, Jan. 3, 1989, titled "Method and Apparatus for Identifying a Faulted Phase," (originally assigned to Westinghouse Electric Corp.; reassigned on Jun. 7, 1990 to ABB Power T&D Company, Inc.) discloses a technique for identifying faults in a three-phase power transmission line. The disclosed technique involves subtracting a prefault current phasor and a zero-sequence current phasor for each phase from a post-fault current phasor for that phase, and comparing the magnitudes of the resultant phasors.
Another function of protective relaying systems is to estimate the location and resistance of the fault. For example, as described in U.S. Pat. No. 4,906,937, Mar. 6, 1990, titled "Method and a Device for Fault Location in the Event of a Fault on a Power Transmission Line" (assigned to Asea Brown Boveri AB, Vasteras, Sweden), in connection with distance protection devices for protecting cables and overhead or underground power transmission lines, it is normally desirable to estimate the distance from a measuring station to a possible fault and to determine the magnitude of the fault resistance.
The basic principles of fault location and determination of fault resistance are well known. Typically, measured values are obtained with the aid of measuring transformers in a measuring station located adjacent to a protected line. Present-day techniques employ analog-to-digital (A/D) conversion and filtering of the measured values. The filtered digital values are then processed by various equations to determine the fault distance and the magnitude of the fault resistance.
There are several known distance protection equations. Two of the most ordinary ones will be briefly described with reference to FIG. 2A, which depicts a line between stations P and Q on which a fault to ground has arisen at point F. Both of these equations assume knowledge of the faultless line impedance Z.sub.PQ on the protected line segment between two measuring stations P and Q. After the detection of a fault, the voltages U.sub.P and U.sub.Q and the currents I.sub.P and I.sub.Q are measured in the respective stations. To eliminate the need for communication between the stations, the values measured at one of the stations are employed as a starting-point. If the assumption is made that a current I.sub.F flows through a fault resistance R.sub.F, producing a voltage U.sub.F across the fault resistance, the following relationship can be assumed: EQU U.sub.P =U.sub.PF +U.sub.F =.alpha.U.sub.PQ +U.sub.F =.alpha.Z.sub.PQ I.sub.P +R.sub.F I.sub.F ( 0.1)
where .alpha. is a parameter having a value in the range 0 to 1 and is an assumed measure of the fault position, and U.sub.PQ is an estimate of the voltage drop across the whole line. The U.sub.PQ estimate is determined with the aid of I.sub.P, which is measured.
Equation (0.1) is not directly solvable because it contains too many unknown parameters (i.e., U.sub.PF, U.sub.F, .alpha., R.sub.F, I.sub.F are unknown quantities). Therefore, certain assumptions must be made. It is common to assume that the fault current I.sub.F is proportional to the current measured in station P. That is, it is assumed that EQU I.sub.F =k.sub.1 I.sub.P ( 0.2)
This assumption is fulfilled if the voltages U.sub.P and U.sub.Q at P and Q have equal phases and if the phase angles for the impedances from the fault location F to the respective stations P, Q are equal. Equation (0.1) can then be written: EQU U.sub.P =.alpha.Z.sub.PQ I.sub.P +R.sub.F k.sub.1 I.sub.P =.alpha.Z.sub.PQ I.sub.P +R.sub.F1 I.sub.P ( 0.3)
where R.sub.F1 is an apparent fault resistance.
Another variant of the necessary assumption is to assume that the fault current is proportional to the current change at P when a fault has occurred. That is, it is assumed that EQU I.sub.F =k.sub.2 .DELTA.I.sub.P ( 0.4)
Therefore, equation (0.1) can be expressed, EQU U.sub.P =.alpha.Z.sub.PQ I.sub.P +R.sub.F k.sub.2 .DELTA.I.sub.P =.alpha.Z.sub.PQ I.sub.P +R.sub.F2 .DELTA.I.sub.P ( 0.5)
Equations (0.3) and (0.5) each comprise two unknown parameters, .alpha. and R.sub.F1 or R.sub.F2, respectively. This means that a linear regression (or some other appropriate problem solving technique) is required to solve for the unknown parameters.
When distance protection devices with fault location and determination of fault resistance are used in connection with high voltage transmission lines, capacitive voltage transformers (CVTs) are usually used for the voltage measurement. It is well known that such voltage measurement devices cause measurement error voltages, called "CVT transients."
The above cited U.S. Pat. No. 4,906,937 describes a fault location system that specifically addresses the problem of CVT transients. The disclosed system is depicted schematically in FIG. 2B. As described in the patent, phase voltages U.sub.P and phase currents I.sub.P are measured on a high voltage network RST at a measuring station P. The patent discloses that either of the following two distance protection equations may be employed as a starting-point: EQU U.sub.PM1 =.alpha.Z.sub.PQ I.sub.P +R.sub.F1 I.sub.P +.DELTA.U.sub.CVT( 0.6) EQU U.sub.PM2 =.alpha.Z.sub.PQ I.sub.P +R.sub.F2 .DELTA.I.sub.P +.DELTA.U.sub.CVT ( 0.7)
If equation (0.6) is made the starting-point, the device for fault location is continuously switched and controls the state of the line. If equation (0.7) is made the starting-point, a least prescribed change of I.sub.P must be assumed to initiate the control of the state of the line. The measuring voltage U.sub.PM is obtained via a capacitive voltage divider 1 and a conventional transformer 2. The current I.sub.P is measured with a current transformer 3. The measured values are low-pass filtered in filters 4 and 5. The filtered voltage and current signals are converted to digital data by analog-to-digital conversion devices (A/Ds) 6, 7. The instantaneous digitalized current and voltage values are supplied to a calculator 8, which processes the data to obtain estimated values of: .alpha., representing the fault position; R.sub.F1 and R.sub.F2, respectively representing the apparent fault resistance; and .DELTA.U.sub.CVT, representing the fault voltage. The values of .alpha., R.sub.F1, and R.sub.F2 are supplied to a logic unit 9 for comparison with upper and lower limit values .alpha..sub.min, .alpha..sub.max, RF.sub.min, and RF.sub.max, respectively. If the .alpha. and RF values lie within the stated limits, a decision B to trip is given.
As indicated by the above discussion of the prior art, some prior art fault location systems make the mathematically convenient assumption that the source and load voltages have equal phases when a fault occurs. However, this assumption is only true if there is no power flow through the line just prior to the occurrence of the fault, which is not typically the case. One goal of the present invention is to provide a fault location system that does not require such an assumption. In addition, some prior art systems do not perform well when there is a large pre-fault power flow; some prior art systems assume that the line and source impedances are the same, which is not always true; and some prior art systems require the protected power system to be modified in some way, e.g., by requiring current and voltage pulses to be placed on the protected lines, as opposed to being passive, i.e., not requiring the protected system to be modified. The present invention is intended to overcome these limitations of the prior art.